After an oil well has been encased and cemented it usually becomes desirable to test the formations penetrated by the wellbore for possible production rates and general productivity of the well. In doing so, a test string containing several different types of tools is utilized to indicate the productivity of the well. These tools may include a pressure recorder, a sample chamber, a closed-in pressure tester, hydraulic jar, one or more packers, and several other tools. In addition, it is preferable to include one or more circulating valves in the string.
The testing procedure requires the opening of a section of the wellbore to atmospheric or reduced pressure. This is accomplished by lowering the test string into the hole on drill pipe with the tester valves and sample chambers closed to prevent entry of well fluid into the drill pipe. With the string in place in the formation, packers are expanded to seal against the wellbore or casing and isolate the formation to be tested. Above the formation the hydrostatic pressure of the well fluid is supported by the upper packer. The well fluid in the isolated formation area is allowed to flow into the drill string by opening the tester valve. Fluid is allowed to continue flowing from the formation to measure the ability of the formation to produce. The formation may then be "closed in" to measure the rate of pressure buildup.
After the flow measurements and pressure buildup curves have been obtained, one or more samples can be caught and then the test string will be removed from the well.
At this point the importance of the circulating valve becomes important. Since it is not desirable to pull the testing string while it may still be full of formation fluids and/or high pressure gas due to the danger of explosion and fire at the surface, plus the resulting contamination of the rig and rig floor with the crude oil and other formation fluids which leads to dangerous and slippery footing, it is almost mandatory that the formation fluids be reversed out under controlled conditions and bled-off away from the rig floor.
To accomplish this reversing out, the inner bore of the test string and drill pipe must be opened near the test tools so that displacement fluid (usually drilling mud) from the annulus can flow into the string to force out the formation fluids at the top where they can be piped away from the rig. The hydrostatic pressure from the displacement fluid is usually considerably higher than the formation pressure due to the high density of the mud and the height of the mud column in the well, therefore displacement from the annulus into the string and up to the surface usually occurs without the need for pumping. All that is required is that the annulus be placed in fluid communication with the bore of the test string at the proper time. During testing and sampling operations the hydrostatic fluids in the annulus must be isolated from the formation fluids to prevent contamination of the tests and samples.
Thus, it is only after the testing and sampling is completed that it is desirable to reverse out the remaining formation fluids in the tubing.
Several methods of accomplishing this are currently in use. One of these methods involves covering the ports through the tubing wall with an inner sleeve which is shear pinned to the tubing wall. When the sleeve is to be opened a weighted bar is dropped through the tubing to strike the sleeve and shear the pins, moving the sleeve downward to uncover the ports and communicate the annulus with the tubing bore. The disadvantages of this device are obvious; a deviated hole may cause the bar to bind in the tubing thereby blocking the tubing and preventing opening of the circulating valve sleeve and removing any chance of reversing out. Also slant holes may reduce the speed of the bar moving down the tubing because of friction between the bar and the tubing wall. A reduction in speed could lower the striking force of the bar to the point where the shear pins will not break and reversing out will not be possible. Also when some of the extremely heavy formation fluids are being recovered the bar may not be heavy enough in these fluids to shear the pins in the circulating valve, or there may be enough trash collected in the valve sleeve to cushion the impact of the bar and prevent shearing of the pins.
Other types of circulating valves utilize reciprocal or rotational movement to operate the valve sleeve. The rotationally operated circulating valve suffers from the disadvantage that often the string may bind in the well bore so that the string has enough flexibility to allow rotation by twisting above the circulating valve. The operator at the surface may have no way of knowing that the rotation is not accomplishing the desired effect, or if he knows he may have no way of correcting it. The same defect occurs in the reciprocating tools, they may become lodged in a deviated well and the circulating valve becomes inoperable.
In addition, the above described circulating valves are unsatisfactory in offshore wells because the blowout preventers must be opened in order to manipulate the drill string or drop the opening bar into the pipe in order to open the circulating valve. This becomes extremely dangerous because well blowout, explosion, and fire become a possibility when the blowout preventers are released and this remains a constant threat until the preventers are closed.
The apparatus of this invention overcomes these difficulties by opening in response to controlled fluctuations in annulus pressure, requiring no manipulation nor activating members inserted onto the tubing.